|
Exhibit 99.1 
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TXU
energy
Luminant
Texas Competitive Electric Holdings Company LLC
Lender Presentation | July 12, 2016
Important Information
This presentation and the oral statements made in connection therewith may contain “forward looking statements” within the meaning of securities laws. Any forward looking statements involve risks, uncertainties and assumptions. Although we believe that the assumptions and analysis underlying these statements are reasonable as of the date hereof, you are cautioned not to place undue reliance on these statements. Forward looking statements include information concerning our liquidity and our possible future results of operations, including descriptions of our business strategies, reserves and cost savings or other benefits we expect to achieve as a result of the proposed transaction.
These statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “target,” “project,” “forecast,” “seek,” “will,” “may,” “should,” “could,” “would,” or similar expressions. These statements are based on certain assumptions that we have made in light of our experience in the industry and our perceptions of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances as of the date hereof. We assume no obligation to and do not intend to update any forward looking statements included herein. You should understand that these statements are not guarantees of future performance or results. Actual results could differ materially from those described in any forward looking statements contained herein as a result of a variety of factors, including known and unknown risks and uncertainties, many of which are beyond our control.
This presentation has been prepared by the Company and includes market data and other information from sources believed by us to be reliable, including industry publications and surveys. Some data are also based on our good faith estimates, which are derived from our review of internal sources as well as the independent sources described above. Although we believe these sources are reliable, we have not independently verified the information and cannot guarantee its accuracy and completeness.
TXU
energy
Luminant
2
Section 1
Introduction
Introduction
In anticipation of exit from bankruptcy protection, Texas Competitive Electric Holdings Company LLC, (“TCEH”, or the “Company”) has received court approval to refinance its existing DIP credit facilities via a DIP “Roll-to-Exit” financing (the “Credit Facilities”)
– The new Credit Facilities will initially refinance the Company’s existing DIP and then will convert to a permanent exit financing upon the Company’s exit from bankruptcy
– The Company anticipates exiting bankruptcy before the end of 2016 as an independent entity (“Reorganized TCEH”)
At closing of the financing, the new Credit Facilities will consist of the following:
– $750 million Senior Secured Revolving Credit Facility (“Revolver”)
– $2,850 million Senior Secured Term Loan B Facility (“Term Loan B”)
– $650 million Senior Secured Funded L/C Facility (“Term Loan C”)(1)
TCEH is the largest electric power generator and retail electric provider in Texas, with over 16 GW of generation capacity and over 1.7 million retail customers ? The Company benefits from an integrated retail electricity and generation platform, which creates an attractive and balanced credit profile under various power price environments, highlighted by:
– A market leading retail business with stable cash flows
– A large, diversified, and efficient generation fleet that complements the retail business
– Significant operating and financial benefits of a combined platform, including risk management and collateral efficiencies
The Company plans to exit bankruptcy with the lowest leverage of any independent power producer (“IPP”) at 1.9x gross and 1.5x net leverage, respectively (based on 2016E EBITDA of $1,520 million) and an extremely conservative Loan-to-Value at ~26% (based on expected TEV of ~$11 billion)
(1) Proceeds at the Funded L/C Facility will be funded into a cash collateral account of the Company to support the issuance of L/Cs.
4
TXU
energy
Luminant
Reorganized TCEH Simplified Capital Structure
Pre-Emergence Post-Emergence
EFH TCEH 1st Lien
“Energy Future Holders(2) Holdings”
Reorganized TCEH
EFIH EFCH
TXU
energy
Luminant
“Energy Future “Energy Future
Intermediate Holdings” Competitive Holdings”
Oncor TCEH Debt Debt
Holdings “Texas Competitive $34.2bn(1) OpCo $3.5bn(3)
Electric Holdings”
TCEH to be spun off as a standalone entity st share of Holders of TCEH 1 Lien claims will receive pro-rata Reorganized TCEH common stock
TXU
energy
Luminant
(1) Excludes value of TCEH 1L swap claims. Includes current DIP credit facilities.
(2) Includes Brookfield, Apollo, and Oaktree.
(3) Includes amounts to be issued as a Funded L/C Term Loan (“Term Loan C”). Excludes capital lease obligations and Tex -La notes.
5
ONCOR
TXU
energy
Luminant
Section 2
Company Overview
Company Overview
TXU
energy
Luminant
Largest ERCOT retail electric provider Largest merchant generation fleet in ERCOT
– 1.7 million total customers(1) – 8,017 MW(5) lignite and PRB coal
– ~88% of meter count and ~53% of load is residential – 3,455 MW(5) natural gas CTs/STs
– 25% residential market customer share, 17% business(2) – 2,988 MW(5) natural gas CCGTs
– Delivers leading profitability despite strong competition and – 2,300 MW(5) nuclear pricing pressure
ERCOT Residential Customer Count (millions)(3) Top Five Competitive Generators in ERCOT(3)
1.5 1.3 16,760
10,586 9,427
Business 0.6 0.4 4,696
0.3 MW 3,517
(6)
Preferred brand with broad recognition across ERCOT 10.1 billion cubic feet of gas storage under management
– DFW, Houston, Corpus Christi, parts of South and West TX – Primarily to fuel peaking generation fleet
Market-leading sales and marketing, customer service, product Commodity hedging and risk management development and customer analytics capabilities to acquire, serve and retain the most valuable customers
(4) Approximately (7) 2015A EBITDA $800 million $1,050 million
Integrated business model creates incremental value when compared to pure play generators or retailers
(1) EFH 10-K 2015.
(2) TXU Energy market share reflects year end 2015 estimated market share. All other competitor brand market share information based on EIA 2014 data set. (3) Figures exclude CPS Energy operating in the San Antonio area, which has opted out of the competitive market.
(4) Both TXU Energy and Luminant include Energy Supply Book (“ESB”) EBITDA contribution, which gets eliminated at the consolidated TCEH level.
(5) Reflects name plate capacity.
(6) Pro forma for Engie acquisition.
(7) Pro forma for $168 million of EBITDA, per unaudited financials, for Forney and Lamar plants (“La Frontera”), which were acquired in April 2016.
7
TXU
energy
Luminant
ERCOT Market Overview
Generator Transmission and Distribution Utility Retailer
Competitive Regulated Competitive
Generating Station Transmission wires Transmission sub-station Distribution Wires Customers
Total Generation in Total Competitive ERCOT (87,400 MW(1)) Total Meters (>7 Million(2)) Customers (>7 Million(2))
16,760 3.3mm(3)
1.7mm
1.3mm
2.3mm(4) (MW) 10,586 9,427
(millions)
(millions)
0.7mm
Capacity Customers 1.0mm(5) Customers
(1) Disclosure Statement, 5/11/2016. Total generation does not reflect all generation sources as calculated by the Public Utility Commission of Texas (PUCT). (2) Per PUCT Report Cards on Retail Competition and Summary of Market Share Data.
(3) EFH 8-K, 5/11/2016.
(4) CNP Investor Presentation March 2016.
(5) AEP’s 2015 10-K, includes Texas Central Company (TCC) and Texas North Company (TNC).
8
TXU
energy
Luminant
Luminant – Largest Generation Fleet In ERCOT
Diversified Portfolio – Nuclear, Gas and Coal
Luminant Geographic Footprint Top Five Competitive Generators in ERCOT(1)
16,760
Comanche Peak (2,300 MW)
Decordova (260 MW)
Lake Hubbard (921 MW) 10,586
9,427
Forney (1,912 MW) MW Lamar (1,076 MW)
Graham (630 MW)
4,696 3,517
Morgan Creek (390 MW)
Permian Basin (325 MW) Monticello (1,880 MW)
Trinidad (244 MW) Martin Lake (2,250 MW)
Big Brown (1,150 MW)
Oak Grove (1,600 MW)
Diversified cash flow contribution(2)
Sandow (1,137 MW)
Stryker Creek (685 MW) By Fuel
Nuclear Coal 32%
37%
Coal Natural gas (Peakers)
Nuclear Natural gas (CCGT) Natural gas
31%
Scale, fuel diversity, and flexibility across the supply stack
(1) Figures exclude CPS Energy operating in the San Antonio area, which has opted out of the competitive market.
(2) 2017E Luminant EBITDA contribution.
9
Large, Diversified, and Efficient Generation Fleet
ERCOT Supply Stack
Illustrative
Average
Peak Demand Demand
MWh) / $ (
Cost Coal Units
Unit CCGT Marginal Units
0 10 20 30 40 50 60 70 80 90
Cumulative Generation Capacity / ERCOT Demand (GW)
Hydro, Wind, and Solar Nuclear Coal CCGT Gas Turbine / Gas Engine Gas Steam Other
Luminant fleet is well positioned throughout the supply stack with diversified fuel sources
Source: Luminant analysis
10
Luminant – Low Cost Nuclear
Comanche Peak
North American Relative Total Cost Comanche Peak (2,300 MW) Comparison for Nuclear Plants(1)
$70
$60
$50
MWh) $40
/ $ ( cost Quartile
$30 Decile
Total $20
Comanche
Comanche Peak
Peak $10
Capacity (MW) 2,300
Capacity Factor – Avg Last 3 Yrs (%) 97.7% $0
70% 80% 90% 100%
Capability Factor (%)
COD 1990 / 1993
Comanche Peak Decile Quartile Median
Location Glen Rose, TX $/MWh $26 $28 $31 $37
Comanche Peak is one of the lowest cost nuclear plants in the U.S. and the second newest(2) nuclear plant in North America
Note: ERCOT refers to Electric Reliability Council of Texas
(1) Benchmarking peer set defined as 18 month fuel cycle U.S. nuclear plants. Data per EUCG May 2016 release for Cost and Capability Factors.
(2) Comanche Peak and Seabrook both went into operation the same month of 1990 with Watts Bar being the only plant that has gone into operation since then as per SNL.
Source: Company Filings, EUCG
11
Luminant - Highly Efficient CCGTs
Forney and Lamar
Forney (1,912 MW)
Lamar (1,076 MW)
Within the top decile by efficiency for CCGTs in ERCOT(1)
Forney Lamar
Capacity (MW) 1,912 Capacity (MW) 1,076
Capacity Factor – Avg Last 3 Yrs (%) 54.3% Capacity Factor – Avg Last 3 Yrs (%) 60.3% COD 2003 COD 2000
Heat rate (Btu / kWh)(2) 6,884 Heat rate (Btu / kWh)(2) 6,865
Location Forney, TX Location Paris, TX
Technology Combined Cycle Technology Combined Cycle
Two of the most efficient and flexible CCGTs in ERCOT
Note: CCGT refers to Combined Cycle Gas Turbine plant
(1) Based on 2015 heat rates, data as per SNL.
(2) Reflect Spring / Fall combined-cycle heat rates, excluding duct burners.
Source: Company Management, Company Filings
Luminant – Two of The Newest Coal Plants in ERCOT
Oak Grove and Sandow Unit 5
Oak Grove (1,600 MW) Sandow Unit 5 (580 MW)
Oak Grove Sandow Unit 5 (1)
Capacity (MW) 1,600 Capacity (MW) 580 Capacity Factor – Avg Last 3 Yrs (%) 87.3% Capacity Factor – Avg Last 3 Yrs (%) 79.6% COD 2010 / 2011 COD 2010 Heat rate (Btu / kWh) 10,843 Heat rate (Btu / kWh) 10,221 Location Franklin, TX Location Rockdale, TX
Technology Steam turbine Technology Steam turbine
Fuel source Luminant mine-mouth Lignite Fuel source Luminant mine-mouth Lignite Env. profile(2) FGD, ACI, SCR, Baghouse Env. profile(2) FGD, ACI, SNCR, Baghouse
Two of the newest coal plants in ERCOT(3), well positioned for environmental compliance
(1) In addition to Sandow Unit 5, Sandow Unit 4 (557 MW) is also located at this plant.
(2) Flue Gas Desulfurization (“FGD”), Activated Carbon Injection (“ACI”), Selective Catalytic Reduction for NOx (“SCR”), Selective Non-Catalytic Reduction for NOx (“SNCR”), and fabric filter systems (“Baghouse”).
(3) Data per SNL. With the exception of Sandy Creek (COD 2013).
Source: Company Filings
13
Luminant – Seasonally Flexible Capacity
Remaining Fleet Optimized to Provide Seasonal Coverage
Facility Capacity (MW) Capacity Factor(1) COD Fuel Technology
Big Brown 1,150 77% 1971 / 1972 Coal ST Seasonal Martin Lake 2,250 66% 1977 / 1978 / 1979 Coal ST Dispatch Monticello 1,880 39% 1974 / 1975 / 1978 Coal ST
Total Seasonal Dispatch 5,280
Decordova 260 NA 1990 Gas CT
Graham 630 NA 1960 / 1969 Gas ST
Lake Hubbard 921 NA 1970 / 1973 Gas ST Simple Cycle Morgan Creek 390 NA 1988 Gas CT and Peakers Permian Basin 325 NA 1988 / 1990 Gas CT
Stryker Creek 685 NA 1958 / 1965 Gas ST
Trinidad 244 NA 1965 Gas ST
Total Gas Plants 3,455
These coal units capture attractive seasonal economics and the peakers are highly strategic assets that are an integral part of the fleet
(1) 2013 – 2015 average capacity factor per Company Management.
14
Overview of Retail
Attractive ERCOT Retail Market Economics of the Retail Business
Represents ~31% of competitively served US retail load Retail businesses engage customer directly Consumption per residential customer ~30% higher than US (willing buyer / willing seller) average Realized margins determined by: Fully de-regulated market – no regulated default rate – Customer type – residential / small business / C&I
50+ Retail Electric Providers (REPs) – Contract term lengths and wholesale rate ownership (1) – Commodity management strategy
Full of customer relationship – billing and service
Anticipated consumption demand growth of ~1-2% annually, Customer contracts can be fixed term or month -to-month
driven by US-leading population growth – Fixed-term contracts provide predictable, stable earnings
– Month-to-month contracts provide flexibility to align with power markets
Key REP Performance Drivers
Incumbent in North Texas since 1882
Customer Service, Focus, and Experience Best PUC Complaints Scorecard ranking among large retailers Over 90% First Call Resolution in 2015 Commodity Management Expertise Integration with Luminant—largest generator in ERCOT
BAV Consulting ranked the TXU Energy brand as strongest in market
Brand Strength and Market Positioning First to market with innovations leveraging the smart grid including Free Nights plan and the TXU Energy mobile app Supports millions of residential customer transactions annually Scalable Back-Office Systems and Competitive Culture Market-leader in cost structure efficiency relative to peers
#7 in 2015 Dallas Morning News “Great Places to Work” Report
(1) Excludes outages handled by transmission and distribution utilities.
15
TXU Energy – Leading Retail Platform
Unique Position as the Top Retailer in Texas Unmatched Brand
Complementary Generation Stable Cash Flows and Capabilities
Multi-channel marketing and sales strategy Luminant’s generation fleet largely present TXU Energy provides stability in varying focused on balancing margin and in the North Texas Region power price environments customer counts Non-integrated businesses can be Historically stable cash flows Despite intense competition, customer exposed to power price volatility and attrition rate has declined to below 1% in incremental collateral costs Integrated Retail / Wholesale Model(3)
2015 (Illustrative)
Market leading brand(1) supporting highest Retail Revenue Rate retained residential customers in Retail Margin incumbent territory / core market Market-based Power Cost Innovative products that drive customer Wholesale Margin value(2)
Dallas
Generation Fuel Costs
Value proposition through straightforward terms of service, total satisfaction Austin
Advantages of Integrated Model guarantee and reliable, accurate bills, Houston outstanding customer experience and San Antonio Stable enterprise earnings ease of doing business Impact of market power price volatility
Corpus Christi
Data driven approach to marketing, minimized due to counter-cyclical nature of service, life-cycle management, and retail and wholesale businesses energy supply Credit / collateral efficient
TXU Energy is the #1 retail electricity company in Texas with 25% residential market share and 1.7 million retail customers
(1) 2015 BAV Consulting Study.
(2) Includes Free Nights, Cash Back Rewards, and Solar Club
(3) Company analysis. Time period is reflective of 2013 – 2015.
16
TXU Energy – Largest Retail Electric Provider In ERCOT
Largest Residential Market Share in ERCOT(1) … … With Stable Customer Base(2)…
25% 1.560 1.516
1.500 1.489 22%
11%
7%
5% 5%
2% 2%
2012 2013 2014 2015 Residential customer count (millions)
… And Strong Cost Management(3)… … Leads to Resilient Retail EBITDA Across Power Price Cycles(4)
$800 $31.11 $778
$23.78
198
124 140
71 83
2012—2014 Avg. 2015 ERCOT North 2012-2014 Avg. 2015 EBITDA
ERCOT North Hub Hub power price EBITDA
Total SG&A per RCE ($/RCE) power price ($/MWh) ($/MWh)
Large scale, strong brand, and excellent operational history has led to steady retail performance
(1) TXU Energy market share reflects year end 2015 estimated market share. All other competitor brand market share information based on EIA 2014 data set. (2) Includes 4Change Energy customers.
(3) “RCE” defined as Residential Customer Equivalent.
(4) ATC power prices per Intercontinental Exchange.
Source: Company Management, Company Filings
17
Section 3
Key Credit Highlights
Key Credit Highlights
Repositioned TCEH will be refinanced at or near the bottom of the commodity cycle with conservative leverage levels and impressive free cash flow generation
1 TXU Energy is the largest retail electric provider in Texas with 1.7 million total customers and a 25% Leading Retail share of the residential market
Platform – Defensible market share
– Stable, dependable cash flows
– Market leader in cost efficiency
2 Luminant has the largest generation fleet in Texas, diversified by fuel and technology, providing it with Large, Diversified, optimal dispatch opportunity along the entire supply stack and Efficient – Nuclear Generation Fleet – Coal
– Gas
3
Integrated business model creates incremental value when compared to pure play generators or
Proven Integrated retailers
Business Model – Cash flow stability through pairing of retail and generation businesses
– Credit efficiencies
4
Conservative Capital
Superior leverage and free cash flow generation metrics provide TCEH with ample liquidity and
Structure and Strong flexibility, especially when compared to its peer group
Cash Flows
5
Right Sized Cost
TCEH continues to right size operations, reduce SG&A, and improve fuel diversity of generation fleet
Structure and
– 35% reduction in SG&A (2009A – 2017E) and 49% reduction in capital expenditures (2013A – 2017E)
Improved Operations
19
1 Leading Retail Platform
Stable Retail Customer Count and EBITDA production
Maintaining Market Share …
(4.0%)
1.560 1.516 1.500 1.489
(2.8%) (1.1%)
(0.7%)
2012 2013 2014 2015
Residential customer count (millions) Attrition rate
… While Growing Sales Volumes (GWh)(1)…
39,570 38,511 41,212 37,994
16,287 15,203 16,601 19,289
23,283 22,791 21,910 21,923
2012 2013 2014 2015
Residential Business markets Column1
… Leading To Stable Performance Across Power Price Cycles(2)
$33.93 $30.50 $26.39 Hub millions) $23.78 prices $ North
( /MWh) $845 $808 $800 $ $682 ERCOT power ( EBITDA 2012 2013 2014 2015 TXU Energy EBITDA Power Prices
(1) Includes 4CE customer counts of ~36K and 2015 load of ~0.5 TWh.
(2) ERCOT North Hub ATC power prices per Intercontinental Exchange. 2014 power price excludes six extreme weather days in Q1 2014. Including extreme weather days, the annual power price was $36.44 / MWh.
Source: Company Management, Company Filings
20
2 Large, Diversified, and Efficient Generation Fleet
Luminant is the largest generator in Texas … … with a well positioned fleet throughout the supply stack
2017E Luminant EBITDA Contribution by Fuel Type Illustrative
16,760 Average Peak
Coal Nuclear Natural gas Demand Demand
31% 10,586 /MWh)
9,427 $
( Coal Units CCGT
32% 4,696 Cost Units
3,517
37% Unit
Marginal
0 10 20 30 40 50 60 70 80 90
Cumulative Generation Capacity / ERCOT Demand (GW)
Poised to Benefit From Power Price Recovery …does not consider current capacity or new
builds at risk potentially resulting in 2021 reserve
ERCOT planned new generation per CDR report … margin significantly below CDR projections
build 8,000 21.6%(11.9%)
new (MW) 6,000 9.7%(8.2%)
4,000 1.5%
Planned capacity 2,000
2021 CDR reserve Coal Reserve New build at risk(2) Adjusted 2021
0 margin retirements margin reserve margin
2016 2017 2018 2019 due to after coal
environmental retirements(1)
Gas Wind Storage Solar regulations
Note: 2016 planned generation per ERCOT December 2015 CDR report. New wind generation is shown at 100% capacity and
is not adjusted for the 12% and 56% reserve margin adjustment applied to non-coastal and costal wind, respectively. Note: Adjusted reserve margin subtract at risk MWs from CDR report load.
Source: ERCOT May 2016 CDR report, ERCOT December 2015 CDR report Source: ERCOT May 2016 CDR report, SNL, Wall St. research
Luminant fleet is well positioned for lower than projected reserve margins due to coal retirements and uncertainty around new builds
(1) Represents ~8.6GW (over 10% of ERCOT capacity); per SNL and Wall Street research.
(2) Assumes 5.9 GW of new build capacity at risk due to need to raise capital. New builds at risk include Texas Clean (240 MW), La Paloma, (730 MW), FGE (1,494 MW), Pondera King (900 MW), Indeck
Wharton (654 MW), and Pinecrest Energy (785 MW) and other wind (1,116 MW) per market participant’s presentations, Wall St. research, and SNL.
21
3 Proven Integrated Business Model
Integrated and Complementary Business Leads to Value Creation …
Wholesale / Generation
Largest generator of ERCOT electricity
Qualified Scheduling Entity balancing total TCEH load
Participates in ERCOT congestion auctions
Manages TCEH renewable energy credits
Buys and sells third party power as needed
Proven integrated risk management of generation and retail positions
Counteracts weather and economic swing
Manages congestion costs
Executes bilateral procurement transactions
Buys renewable energy credits
Procures ancillary services requirements
Efficient cost structure
Retail / Customers
ERCOT’s largest REP
Offers full suite of traditional and innovative products and services
Load is 100% supplied by Luminant Energy
Diverse customer load profiles including residential, small business and large industrial customers
Efficient cost structure
Advantages of the Integrated Business Model
Higher margins compared to generators with no retail due to integrated business model(1) Excess generation volumes can be utilized to cover full requirements of retail contracts
- Avoids negative impacts of Polar Vortex or 2011 ERCOT summer
Retail competition declines as volatility challenges risk management capabilities of non -integrated competitors Provide counter balance for wholesale power and stabilizes cash flows Avoids ISO collateral requirements
Avoids “bid-ask” cost of transacting on exchanges
Integration of retail and generation derisks combined business and increases cash flow stability
(1) Defined as 2015A EBITDA / 2015A TWh.
22
3 Proven Integrated Business Model
… And Produces Diversified, Balanced EBITDA Contribution
Increasing power prices benefit generation while declining power prices benefit retail
Luminant EBITDA did not realize full benefit from increasing power prices in 2014 due to
Comanche Peak’s scheduled refueling outage(1)
$2,500 $35.00
$33.93
$2,000 $157
$167
$168 /MWh)
$30.00( $
$30.50
millions) $1,500 prices
$1,062
$
( $1,070 $885 power
EBITDA $1,000 Hub
$25.00 North
$500 $23.78
$808 $800
$682 ERCOT
$0 $20.00
2013 2014 2015
TXU Energy Luminant excl. CHP(2) Forney and Lamar(3) ERCOT North Hub Settled Power Prices(4)
Proven integrated retail and generation business model enables TCEH to generate significant EBITDA in a variety of power price environments
Significant synergies between businesses
Complementary generation and retail resulting in balance sheet efficiencies and reduced supply risks / collateral needs for TXU Energy as a result of Luminant’s long generation position
The complementary relationship between TXU Energy and Luminant has been proven to consistently produce significant EBITDA
Note: Both TXU Energy and Luminant include Energy Supply Book EBITDA contribution, which gets eliminated at the consolidated TCEH level. (1) Outage was extended by one month for repairs.
(2) Corporate Hedge Program (“CHP”) was the Company’s long-term natural gas hedge program from 2007 – 2014.
(3) Forney and Lamar EBITDA per unaudited financials and includes hedges.
(4) 2014 power price excludes six extreme weather days in Q1 2014. Including extreme weather days, the annual power price was $36.44 / MWh.
Source: Company Management
23
4 Conservative Capital Structure and Strong Cash Flows
Conservatively Financed Capital Structure …
Total Debt / 2016E EBITDA(1) Total Debt / TEV(2)
6.5x 6.2x 6.1x 80% 82%
77%
71%
4.9x
1.9x 26%
TCEH TCEH
… Supported by Balanced Business Model …
Retail vs. Generation – Contribution to 2015 EBITDA
TCEH
Retail Generation
TCEH contemplated capital structure is right sized for current market conditions, and by far the most conservative among unregulated power companies
(1) 2016E EBITDA includes La Frontera EBITDA from April 2016 – December 2016
(2) Assumes TCEH TEV of $11,103 million; calculated as Equity of $8,227 million plus TCEH debt of $2,876 million. Equity of $8,227 million calculated as mid point of Evercore valuation of $11,600 million per Disclosure Statement Exhibit G less net debt of $2,321 million less present value of Tax Receivable Agreement of $1,052 million.
Source: Company Management, Company Filings
24
4 Conservative Capital Structure and Strong Cash Flows
… And Best In Class Collateral Coverage
$14,000
$12,000 $11,600
$10,454
$9,852
$10,000
millions $8,000
in
$ $6,000
$4,000 Exit Financing
$2,850(1)
$2,000
$0
Current Pre-Petition Debt Trading Level (2) Trading Multiples(3) POR Valuation(4)
Midpoint $9,852 $10,454 $11,600
Loan -to-Value 28.9% 27.3% 24.6%
Collateral Coverage 3.5x 3.7x 4.1x
Significant collateral coverage with an average LTV of ~27%
(1) Excludes $650 million Funded L/C Term Loan (“Term Loan C”).
(2) Trading levels as of 7/10/2016. Assumes cash at exit of $555 million per Sources and Uses.
(3) 2017E EBITDA of $1,315 million; 2017E multiple range of 7.1x – 8.8x, based on trading levels of Calpine, Dynegy, and NRG.
(4) Reorganized TCEH TEV, as per valuation analysis by Evercore, sourced from 5/11/2016 Plan Of Reorganization; Exhibit G. Evercore’s valuation analysis for Reorganized TCEH includes a discounted cash flow analysis and peer group company analysis.
25
5 Right Sized Cost Structure and Improved Operations
Responding to low power prices, Luminant manages plant capital, fuel and O&M expense in order to increase / maximize profitability
Corporate overhead rationalized by 2017 to reflect the size and scope of the emerged company
Luminant created flexibility in its units by converting to seasonal operations that lower run times leading to reduced maintenance and total variable costs
Acquisition of Forney and Lamar plants diversifies the fleet, increases gas capacity from 25% to 38%, while decreasing coal from 58% to 48% Adds assets able to follow load changes Low heat rate units are very competitive in ERCOT Assets purchased at a fraction (~60%) of replacement cost Attractive location near Dallas/Ft Worth load pocket
Reduced Reduced
Cost Cost Structure Structure
Improved Fleet Diversity
SG&A Expenses 2009 – 2017E; $ in millions(1)(2)
35% reduction in SG&A
$983
$794 $744 $641
2009 2014 2015 2017E
Capital Expenditures 2013A – 2017E; $ in millions
$603 49% reduction in CapEx
$309
2013A 2017E
Pre Forney and Lamar Post Forney and Lamar
Acquisition (MW) Acquisition (MW)
Natural Natural
Gas Gas
25%
38%
58% Coal 48% Coal
17%
Nuclear 14%
Nuclear
13,772 MW 16,760 MW
Substantial costs savings achieved with multiple levers available for EBITDA upside
(1) Total SG&A figures per EFH 10-Ks. Total SG&A figures include Franchise and Revenue-Based Taxes that were grouped into SG&A in 2015. Previous years restated to show SG&A on a comparable basis.
(2) Reorganization costs through 4/28/2014. From 4/29/2014 reorganization costs not included in SG&A.
26
Section 4
Financial Overview
Key Projection Assumptions
Gas Prices (Houston Ship Channel)(1)(2) ERCOT North Hub ATC Power Prices (1)(3)
$5.00 $40.00 Increase due to polar vortex
$4.33 $33.93
Increase due to polar vortex
$4.00
$30.00 $34.76
$32.84
$3.69 $30.50 $30.97
$3.00 $28.93
$3.03 $3.10 $3.18 $27.22
/mmBtu) $2.79 $2.91 $ /MWh) $20.00 $23.78 $24.99
$(
( $2.00 $2.57 $2.46
$1.00 $10.00
2013A 2014A 2015A 2016E 2017E 2018E 2019E 2020E 2021E 2013A 2014A 2015A 2016E 2017E 2018E 2019E 2020E 2021E
Generation Implied Market Heat Rates (ERCOT North Hub)(1)(4)
100.00 12.00
Drop from 2016 to 2017 due to
90.00 seasonal dispatch of Monticello and 11.00
89.67 Martin Lake
80.00 85.39 10.96
10.00 10.61
70.00 80.33 80.03 10.13 10.24
(TWh) 9.00 9.76 9.96
60.00 72.41 70.86 70.87 69.34 67.28(mmBtu/kWh) 9.26
50.00 8.00 8.43
8.26
40.00 7.00
2013A 2014A 2015A 2016E 2017E 2018E 2019E 2020E 2021E 2013A 2014A 2015A 2016E 2017E 2018E 2019E 2020E 2021E
Conservative forecast not reflecting upside volatility in ERCOT
Note: Includes Forney and Lamar plants.
(1) Projected natural gas prices, heat rate, and power prices are as of 12/31/2015 for 2016E-21E. Historical ERCOT North Hub ATC power prices per Intercontinental Exchange. 2014 power price
excludes six extreme weather days in Q1 2014. Including extreme weather days, the annual power price was $36.44 / MWh.
(2) Projected natural gas prices reflect Houston Ship Channel index prices for 2016-19E, escalated at 2.4% annually for 2020-21E.
(3) Projected power prices developed by multiplying projected natural gas prices with projected heat rates.
(4) Projected heat rates reflect observable market rates for 2016-17E with a Company proprietary model thereafter.
Source: Disclosure Statement, 5/11/2016
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Historical and Projected Financials
EBITDA(1) ($ in millions)
$2,923
$2,296
$1,722 $1,733
$1,520 $1,315 $1,327 $1,397 $1,517
2013A 2014A 2015A 2016E 2017E 2018E 2019E 2020E 2021E
TXU Energy Luminant excl. CHP(3) Forney and Lamar Corporate Hedge Program (“CHP”)
Capital Expenditures(1)(2) ($ in millions)
$625 $503 $520
$384 $309 $387 $335 $330 $387
2013A 2014A 2015A 2016E 2017E 2018E 2019E 2020E 2021E
TCEH Forney and Lamar
Unlevered FCF(1) ($ in millions)
$1,932
$1,413 $1,330
$982 $917 $1,023 $964
$781 $815
2013A 2014A 2015A 2016E 2017E 2018E 2019E 2020E 2021E
TCEH Forney and Lamar
High free cash flow conversion driving stable and sustainable cash flows
(1) Includes Forney and Lamar plants. Historical Forney and Lamar EBITDA, CapEx, and Unlevered Free Cash Flow contribution not part of the Company’s historical financial statements and shown separately. Forney and Lamar EBITDA per unaudited financials and include hedges. 2016E EBITDA includes Forney and Lamar fro m April 2016 – December 2016.
(2) Includes nuclear fuel, buyout of CT leases, and technology spend. Excludes capitalized interest. 2016E CapEx includes Forney and Lamar from April 2016 – December 2016.
(3) Corporate Hedge Program (“CHP”) was the Company’s long-term natural gas hedge program from 2007-2014. 2016E FCF includes Forney and Lamar from April 2016 – December 2016.
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Strong Deleveraging Profile
Total Debt(1) ($ millions) Net Debt(2) ($ millions)
$1,561
$2,837 $2,802
$2,769 $2,738 $971
$2,708
$277
($529)
($1,285)
2017E 2018E 2019E 2020E 2021E 2017E 2018E 2019E 2020E 2021E
Total Debt / EBITDA Total Debt / Capitalization (3)
2.2x 2.1x 2.0x 25.6% 25.2% 24.9% 24.7% 24.4%
1.8x
1.6x
2017E 2018E 2019E 2020E 2021E 2017E 2018E 2019E 2020E 2021E
TCEH is expected to generate sufficient cash flows to fully repay the proposed Term Loan B facility before the end of 2020
(1) Excludes $650 million Funded L/C Term Loan (“Term Loan C”).
(2) Current Plan contemplates formation of PrefCo for tax purposes. Net debt would be lower due to a higher cash balance given issuance of approximately $50 million of preferr ed shares. (3) Assumes $11,103 million TEV per Sources and Uses.
30
Section 5
Transaction Overview
Sources and Uses and Pro Forma Cap Table
Step 1: New DIP Facility on 8/1/2016
Sources Uses
New Term Loan B $2,850 Repay existing DIP Revolver draw(1) $1,455
New Funded L/C Term Loan (“Term Loan C”) 650 Repay existing DIP Term Loan B 625
Release existing DIP L/C Facility cash 800 Repay existing DIP Term Loan supporting L/C Facility 800
New L/C Facility cash to balance sheet 650
Cash to balance sheet 632
Issuance fees and OID 138
Total Sources $4,300 Total Uses $4,300
Step 2: Roll to Exit Facility at Emergence on 12/31/2016
Sources Uses
Cash from balance sheet(3) $998 Emergence related expenses $145
Payout to TCEH unsecured creditors 550
Projected cash utilization (from 8/1/2016 – 12/31/2016)(2) 303
Total Sources $998 Total Uses $998
Step 2
Capitalization Current Step 1 Adjustments Pre-Emergence Adjustments Post-Emergence PF x2016E EBITDA% of TEV (6)
Cash and cash equivalents $921(4) $632 $1,553($998) $555
L/C Facility cash collateral 800(150) 650—650
Existing $1,950 million DIP Revolver $1,455(1)(1,455) — -
Existing DIP Term Loan B 625(625) — -
Funded L/C Facility 800(150) 650—650
New $750 million Revolver — — -
New $2,850 million Term Loan B—2,850 2,850—2,850
Total TCEH Post-Emergence Debt(5) $2,080 $2,850 $2,850 1.9x 26%
Total TCEH Post-Emergence Net Debt(6)—$2,321 1.5x 21%
TCEH Pre-Petition Funded Debt
Senior Secured First Lien Credit Facilities $22,636 $22,636(22,636) -
Other pre-petition debt 9,450 9,450(9,424) 26
Total TCEH Pre-Petition Debt $32,086 $32,086 $26
Total TCEH Debt $34,166 $34,936 $2,876 1.9x 26%
Equity(7) — 8,227 8,227
Total TCEH Capitalization(7) $34,166 $34,936 $11,103 7.3x 100%
2016E EBITDA(8) $1,520 $1,520
Includes accrued interest on DIP credit facilities of $7 million.
Includes final adequate protection payments of $110 million.
Current Plan contemplates formation of PrefCo for tax purposes.Includes $50mm use of cash from balance sheet, which reflects approximately $50 million in proceeds from preferred shares issuance.
Includes unrestricted cash of $250 million, unencumbered cash available at emergence of $164 million, and pre -filing restricted cash balance under a TCEH pre-petition LC Facility of $507 million.
Excludes $650 million Funded L/C Facility.
Includes $26 million of capital lease obligations and Tex -La notes.
Common equity of $8,227 million calculated as mid point of Evercore valuation of $11,600 million per Disclosure Statement Exhibit G less net debt of $2,321 million less present value of Tax Rec eivable Agreement of $1,052 million. TEV of $11,103 million; calculated as equity of $8,227 million plus TCEH debt of $2,876 million .
Includes Forney and Lamar EBITDA for April 2016 – December 2016.
32
Summary Term Sheet
Borrower: Texas Competitive Electric Holdings Company LLC (the “Company”) or, after exit/conversion a new domestic entity resulting from
consummation of the Plan that succeeds to the business and operations of the Company
Guarantees: Certain domestic subsidiaries of the Borrower and the Borrower’s immediate parent company
Secured by a first priority security interest in all tangible and intangible assets, and equity of subsidiaries, of the respective Borrower and
Security: the Guarantors subject to the liens securing certain reclamation obligations in favor of Railroad Commission of Texas and other
customary exceptions
Tranche Amount ($ millions) Coupon (bps) OID LIBOR floor Maturity
Revolving Credit Facility (“RCF”) $750 L+TBD TBD NA 5 years(1)
Facility:
Term Loan B (“TLB”) $2,850
L+TBD TBD 1.00% 7 years(2)
Term Loan C (“TLC”) $650
Incremental 1st lien secured debt limited to the sum of (i) $1.0 billion, plus (ii) an unlimited amount subject to 3.0x 1st lien Net Secured
Accordion: Leverage, with 50bps of MFN for 12 months(3)
Voluntary RCF: prepayable at par at any time
prepayments: TLB / TLC : 101 soft call for 6 months
TLB: 1.0% amortization, payable quarterly
Mandatory TLC: None until Term Loan B repaid
prepayments: Customary provisions for asset sale, casualty, and debt proceeds, applied first to the TLB until fully repaid, and thereafter to the TLC
Financial covenants: RCF: Springing leverage covenant based on 30% utilization, set at 4.25x 1st Lien Net Secured Leverage
TLB / TLC: none
Other covenants customary for transactions of this nature, including, but not limited to: (i) limitation on debt, (ii) limitation on mergers and
Negative covenants: acquisitions, (iii) limitation on restricted payments, (iv) limitation on asset sales, (v) limitation on liens, and (vi) limitations on transactions
with affiliates
To include the receipt of Confirmation/Approval order, compliance with a $500 million minimum liquidity covenant and compliance with
Conversion conditions the financial maintenance covenant (if in effect), no existence of a MAC or a material event of default, fees paid, accuracyof specified
at exit: representations, and receipt of conversion notice, solvency certificate, pro forma balance sheet and security documents
DIP maturity is October 31, 2017 or, if exit/conversion occurs, 5 years from the Closing Date.
DIP maturity is October 31, 2017 or, if exit/conversion occurs, 7 years from the Closing Date.
Includes the ability to raise up to $975 million of 1st lien TLC to cash collateralize LCs, solely to the extent required by the RCT in lieu of providing a lien or self bonding.
33
Timeline
Week of Key Financing Dates
11-Jul July 12: Bank meeting in New York
25-Jul July 26: Commitments due from lenders
Finalize and execute legal documentation
1-Aug
Close and fund transaction
34
Appendix
Tax Receivables Agreement (“TRA”)
Long term agreement between Reorganized TCEH and the TRA rights holders (initially, the TCEH First Lien creditors)
Allows holder to monetize 85% of the benefit from the tax basis step-up triggered by contemplated emergence transactions and from the tax basis of the Forney and Lamar assets
Company keeps the remaining 15% of the benefit
Value of TRA calculated as 85% of the present value of the projected difference between
Reorganized TCEH’s tax liability with the step-up (and Forney and Lamar tax basis) and its tax liability without the step-up (and Forney and Lamar tax basis)
Reorganized TCEH would make TRA payments only to the extent actual cash savings from the step-up (and Forney and Lamar basis) are realized
TRA structurally subordinated to Debt issued by OpCo
Shareholders
Management
Tax Receivable Agreement
Reorganized TCEH
OpCo
Debt
TRA obligations shall be at the parent company (Reorganized TCEH) level, and be structurally subordinated to debt issued by the Company
36
Unlevered Free Cash Flow Build
2016E(1) 2017E 2018E 2019E 2020E 2021E
EBITDA $1,520 $1,315 $1,327 $1,397 $1,517 $1,733
Capital Expenditures(384)(309)(387)(335)(330)(387)
(incl. Nuclear Fuel)
Working Capital(123) 70 8(16)(16)(22)
Tax Payments(24)(65)(15) 16(17)(115)
Tax Receivable
Agreement Payments 0 0(78)(104)(90)(180)
Other(2)(209)(28)(39)(41)(41)(65)
Unlevered Free Cash $781 $982 $815 $917 $1,023 $964
Flow
(1) 2016E pro forma for Forney and Lamar from April 2016 – December 2016.
(2) Other cash flow items include margin deposits and trading premiums, mining reclamation payments, contributions to the nuclear decommissioning trust, pension and OPEB related expenses / contributions, property taxes, and other miscellaneous items.
Source: Company Management
37
TCEH Reg G Financials
Net Loss to EBITDA Reconciliation
2013 2014 2015
Net loss attributable to TCEH($2,197)($6,229)($4,677)
Income tax benefit(732)(2,320)(879)
Interest expense and related charges 1,916 1,749 1,289
Depreciation and amortization 1,333 1,270 852
EBITDA before other adjustments 320(5,530)(3,415)
Amortization of nuclear fuel 153 141 146
Purchase accounting adjustments 23 23(16)
Impairment and write-down of other assets 38 4,940 2,626
Impairment of goodwill 1,000 1,600 2,200
Unrealized net (gain) loss resulting from hedging transactions 1,091 370(119)
Transition and business optimization costs 21 20 14
Transaction and merger expenses 39 10 0
Reorganization items 0 520 101
Restructuring and other 81 35 17
EBITDA after other adjustments 2,766 2,129 1,554
Forney and Lamar EBITDA 157 167 168
EBITDA (including Forney and Lamar) $2,923 $2,296 $1,722
Source: Company Management
38
TCEH Reg G Financials
Unlevered Free Cash Flow Reconciliation
2013 2014 2015
Cash provided by (used in) operating activities($270) $444 $237
Capital expenditures(1)(472)(336)(337)
Nuclear fuel purchases(116)(77)(123)
Purchase of right to use certain computer-related assets from affiliate(29)(4) 0
Acquisition of combustion turbine trust interest(40) 0 0
Proceeds from sale of nuclear decommissioning fund trust securities 175 314 401
Investments in nuclear decommissioning fund trust securities(191)(331)(418)
Other net investing activities(11)(32)(13)
Interest paid (1) 2,686 1,252 1,298
Interest income received(6) 0(1)
Restructuring professional fees paid 70 116 207
Pension and other payments to affiliates 0(19)(20)
Rounding 1 1 0
TCEH Unlevered free cash flow 1,797 1,328 1,231
Forney and Lamar unlevered free cash flow 135 85 99
Unlevered free cash flow $1,932 $1,413 $1,330
(1) Includes capitalized interest.
Source; Company Management
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